Download 2009 RPS RFO Att K - LCBF Evaluation Criteria

2011 RPS RFO
Attachment K
PG&E’s Description of its RPS Bid Evaluation, Selection Process and Criteria
I. Introduction
A. Establishment of the Least Cost Best Fit Process
Decision D.03-06-071 and D.04-07-029 adopted criteria for the rank ordering and selection
of least cost, best fit renewable resources for use in RPS solicitations. Furthermore, D.05-07039 directed the IOUs to make their bid evaluation process transparent to their Procurement
Review Groups (PRG) and the California Public Utilities Commission (CPUC).
In addition, D.06-05-039 required “each utility to provide a report when it submits its short
list of bids. Each utility should also serve a copy on the service list, and make the report
available to the fullest extent possible to any other person or party expressing interest, subject
to confidential treatment of protected information. The report shall explain each utility’s
evaluation and selection model, its process, and its decision rationale with respect to each
bid, both selected and rejected.”
D.06-05-039 also required each IOU to hire an independent evaluator (IE) “to separately
evaluate and report on the IOU’s entire solicitation, evaluation and selection process for this
and all future solicitations. This will serve as an independent check on the process and final
selections. The Independent Evaluator’s preliminary report should be provided with the
IOU’s shortlist, and a final report with the AL for approval of selected bids.”
The Scoping Memo for R.06-05-027, issued August 21, 2006, required that the IOUs submit
their first written report describing their bid evaluation criteria and selection process on
September 29, 2006, and that IOUs resubmit the report with their short lists (including more
information, such as bid analysis, as necessary). Additionally, in the RPS Transparency
Workshop held on December 15, 2006, the CPUC’s Energy Division staff proposed,
pursuant to D.06-05-039, a template to be used for future evaluation criteria and selection
reports (“LCBF Written Report”).
D.06-05-039 further required that each IOU include certain elements, subject to confidential
treatment of protected information, in each report. These elements include bid-specific price
information, the evaluation and scoring of each bid, and the decision rationale with respect to
each bid, both selected and rejected. D.11-04-030 added that each utility should describe
LCBF treatment of congestion, and to certain price data available.
B. Goal of PG&E’s bid evaluation, selection criteria, and processes
The goal of the bid evaluation, selection criteria, and selection processes is to produce a short
list of offers for negotiations which will ultimately result in energy procurement of 1-2% of
PG&E’s load.
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II. Bid Evaluation and Selection Criteria
A. Description of Criteria
Offers are ranked according to Market Valuation, as defined below. In accordance with
CPUC decision D.04-06-013, Transmission Adders and Integration Costs1 are excluded from
the Market Valuation used for the initial ranking. The Offers are located within their
appropriate transmission clusters and ranked according to the initial ranking. The
appropriate Transmission Adder, if any, is subtracted from the Market Valuation, resulting in
a Net Value. The Offers are re-ranked by Net Value. Using the project-specific information
and scores from each of the other evaluation criteria, PG&E decides which Offers to include
and which ones not to include on the Shortlist. The final Shortlisted Offers should provide
the “least cost-best fit” renewable energy for PG&E’s customers.
B. Overview of the Ranking Methodology
PG&E evaluates each bid in terms of the following attributes:
1.
2.
3.
4.
5.
Market Valuation
Portfolio Fit
Project Viability
RPS Goals
Transmission Adder
Where applicable, except Transmission Adder, a larger (more positive) number is to be
considered better—all else being equal—than a smaller (less positive) number. Solicited
bids are evaluated using the following step-by-step process:
1. The Market Valuation is computed for each Offer. Portfolio Fit is assessed for each
Offer. Then, each of the scores for Project Viability and RPS Goals are assessed and
collected.
2. The Offers are then sorted by transmission cluster and Offers within each cluster are
ranked by Market Valuation.
3. The initial ranking results in the allocation of existing transmission and any costs
associated with transmission upgrades based on the Transmission Ranking Cost Report
(TRCR) to projects with highest market value. Next, the lower of either the cost of a
Transmission Adder or an alternative commercial arrangement is included in the bid market
valuation. The result is called the Net Value.
4. Once the Market Valuation has been adjusted by transmission value, the other attributes
are considered and applied to the bid to arrive at its final place in the ranking. After
transmission-adjusted Market Valuation, of the remaining attributes, Project Viability has the
1
Integration Costs are assumed to be zero until further guidance from the CPUC or CEC.
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greatest qualitative effect on the ranking. The set of highest ranked Offers which allow for a
reasonable probability of satisfying PG&E’s procurement goal is selected for the Shortlist.
1. Market Valuation
a. Overview of the Market Valuation Criterion
Market valuation considers how an Offer’s costs compares to its benefits, from a market
perspective. Costs include fixed and variable components representing all anticipated significant
relevant costs, including Transmission and Integration cost adders. Benefits include energy,
capacity, and ancillary services. Costs and Benefits are each quantified and expressed in terms
of present value (2011 dollars) per MWh. Market Value is Benefits minus Costs, and is
expressed in terms of levelized price, that is, present value per MWh (2011 dollars and 2011
MWh). All energy benefit calculations use a Locational Marginal Price (LMP) multiplier to
comprehend the locational value of the energy delivered. Differences in LMP prices reflect both
congestion and losses between areas. The specific multiplier is based on recorded MRTU data
for the period July to February 2011. A summary of LMP multipliers for each LMP zone is
included as Table 1 below. More detailed LMP multipliers can be downloaded from PG&E’s
website at www.pge.com and clicking on the 2011 RPS RFO link.
TABLE 1
Locational Marginal Price (LMP) Aggregation Multipliers2
Descriptive Names
PG&E Central Coast
PG&E East Bay
PG&E Fresno
PG&E Fulton Geysers
PG&E Humboldt
PG&E Los Padres
PG&E North Bay
PG&E North Coast
PG&E North Valley
PG&E Peninsula
PG&E Sacramento Valley
PG&E South Bay
PG&E San Francisco
PG&E Sierra
PG&E San Joaquin
PG&E Stockton
CAISO
APNodes
On
Peak
Off
Peak
PGCC
PGEB
PGF1
PGFG
PGHB
PGLP
PGNB
PGNC
PGNV
PGP2
PGSA
PGSB
PGSF
PGSI
PGSN
PGST
1.006
1.000
0.994
1.001
1.059
1.000
1.004
1.028
0.965
1.016
0.985
1.009
1.044
0.974
0.945
0.991
1.008
1.001
1.003
0.993
1.073
1.000
1.000
1.007
0.978
1.012
0.996
1.009
1.026
0.987
0.958
0.994
2
LMP multipliers shown are a simple average over hours and months. Contract valuations use disaggregated values
for different months and peak and off-peak periods.
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So Cal Edison Core
So Cal Edison North
So Cal Edison West
So Cal Edison High Desert
So Cal Edison Low Desert
So Cal Edison North West
San Diego Gas & Electric Core
SCEC
SCEN
SCEW
SCHD
SCLD
SCNW
SDG1
0.995
0.989
1.016
0.940
0.992
1.007
0.997
0.998
0.997
1.011
0.947
0.986
1.011
0.999
The map for CAISO APNodes is for illustrative purposes only.
Offers are classified into two types based upon how they are financially modeled: 1) forward
contracts and 2) dispatchables. How benefits and costs are calculated varies with each of the two
types of Offers. Since the valuation method for each Offer determines how the Offer is valued,
the calculation of Benefits, Costs, and Market Value is described below. Whether an Offer is for
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a power purchase agreement (PPA) or purchase and sales agreement (PSA) does not affect
valuation. Offers of “sites for development” are not discussed here.
b. Calculation of Benefits, Costs, and Market Value for Each Offer
Type

Forward Contracts
The term “forward contract” is used to describe an Offer that provides energy with no dispatch
flexibility. This type of Offer includes Baseload, As-Available, and REC plus Energy products..
Quantification of Benefits: The benefits of forward contract Offers include energy, capacity,
and ancillary services. Benefits are measured in units of present value per MWh (2011 dollars
and 2011 MWh).
Energy benefit, for each hour of delivery, is the quantity of energy delivery for an hour
times the forward energy price for that hour. The quantity of energy delivery for each
hour is determined by the hourly generation profile of the offer. Discounted hourly
energy benefit is summed across hours of delivery, and summed across years. The total
discounted benefit is then divided by total discounted MWh of energy, expressed in terms
of present value per MWh.
Capacity benefit for Resource Adequacy (RA), for year of availability, is the monthly
quantity of qualifying capacity multiplied by the monthly capacity value, discounted to
2011 dollars and summed across years. The total discounted capacity benefit is then
divided by total discounted MWh of energy, expressed in terms of present value per
MWh. PG&E will use the most current, CPUC-adopted methodology for calculating net
qualifying capacity. The methodology at the time of RFO issuance was established in D.
09-06-028. Pursuant to this decision, for intermittent energy (e.g., wind and solar)
products, the qualifying capacity for each month is determined by the capacity that has an
exceedance factor of 70% for the five on-peak hours. That is, for 70% of the time, per
hour energy generation for the five RA counting peak hours (HE14-HE18 for April
through October, and HE17-HE21 for the rest of the year) is greater than or equal to the
qualifying capacity. For other types of non-dispatchable products excluding biomass and
geothermal, the qualifying capacity is determined by the monthly average of the five RA
counting generation profile of the offer. The qualifying capacity for biomass and
geothermal Offers are the maximum monthly generation capacity.
For Offers whose location would contribute to PG&E’s satisfaction of its Local Capacity
Requirement as specified by the CAISO and adopted by the CPUC, the capacity
attributable to the Offer may be valued at a premium relative to the value of capacity that
satisfies only system needs.
Offers classified as forward contracts are assumed to provide zero ancillary services
benefit.
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Quantification of Costs: Cost is determined by the expected payments under each Offer, plus
Transmission and Integration cost adders, which are determined using the methodology adopted
by D.04-06-013 and D.05-07-040.
PG&E’s payments for each Offer are determined by the Offer’s price multiplied by the
appropriate Time of Delivery (TOD) factors if applicable, as specified in the RPS
Solicitation Protocol. Cost is measured in units of present value per MWh (2011 dollars
and 2011 MWh).
In the case of PSA Offers, PG&E’s payments for each Offer are replaced by the revenue
requirements, fixed and variable operations and maintenance costs, and ownership costs.

REC-Only Offers
The term REC-only is used to describe an Offer that provides renewable energy credits, without
any associated energy.
Quantification of Benefits: Since there is no associated energy or capacity, there is no energy
or capacity benefit.
Quantification of Costs: Cost is determined by the expected payments under each Offer. Since
there is no associated energy or capacity, there are no Transmission and Integration cost adders.

REC plus Energy Offers
The term REC plus Energy is used to describe an Offer that provides renewable energy credits,
as well as renewable energy.
Quantification of Benefits: Since benefits of RECs are not explicitly evaluated, a REC plus
Energy contract will be valued exactly the same as a Forward contract.
Quantification of Costs: Cost is determined by the expected payments under each Offer, and is
measured in units of present value per MWh (2011 dollars and 2011 MWh). TOD factors will
not apply. .

Dispatchables
The term “Dispatchables” is used to describe Offers which provide some flexibility in their
dispatch.
Quantification of Benefits: Benefits include energy, capacity, and ancillary services.
Benefits are measured in units of present value per MWh (2011 dollars and 2011 MWh).
Energy benefits of a dispatchable type of Offer are calculated as a daily exercise of
European call options. Additional details depend on the nature of the particular
characteristics of a specific Offer.
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Capacity benefit for a dispatchable type of Offer is calculated the same way as described
above for the forward contracts type of Offer. The quantity of qualifying capacity is
determined by the performance requirements of the Offer and the characteristics of a
specific Offer.
Ancillary services benefit for a dispatchable type of Offer depends on the characteristics
of a specific Offer.
Quantification of Costs: The cost represented by a dispatchable type of Offer is calculated the
same way as described above for the forward contracts type, except that PG&E’s capacity
payments for each Offer are determined by the Offer’s pricing multiplied by the appropriate
Time Of Availability (TOA) factors. Cost is measured in units of present value per MWh (2011
dollars and 2011 MWh).

Integration Costs
Integration costs are defined as the costs and values of integrating a generation project into a
system-wide electrical supply. The primary categories of integration costs are regulation, load
following, and shadow capacity. Pursuant to D. 04-07-029, and unless provided further guidance
from the California Public Utilities Commission and/or the California Energy Commission,
PG&E will assume that integration costs are zero.
2. Portfolio Fit
The portfolio fit measure differentiates Offers by the firmness of their energy delivery and by
their energy delivery patterns. A higher portfolio fit measure is assigned to the energy that
PG&E is sure to receive and fits the needs of the existing portfolio. It is extremely important
that PG&E be able to count on energy when planned as part of managing its long term portfolio.
The Portfolio Fit metric is an integer value between 0 and 100, inclusive. It is obtained by
averaging, with equal weighting, the two scores obtained from: 1) the delivery firmness, and 2)
the time of delivery, including the commercial online date. The average value is rounded to the
closest integer (a half-integer value is rounded up). The scores will be accompanied by an
explanation of the rationale behind the scoring.
3. Project Viability
a. CPUC Final Project Viability Calculator
The CPUC developed a Project Viability Calculator (PVC) with stakeholder participation from
utilities, renewable project developers and ratepayer advocates. The CPUC’s PVC, along with
background on its development, instructions for use, and criteria scoring guidelines can be found
on http://www.cpuc.ca.gov/PUC/energy/Renewables/procurement.htm and in the PVC itself.
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2011 RPS RFO
PG&E will evaluate the project viability of each offer using the June 2, 2011 CPUC PVC.
Participants are requested to self-score each of their offers using the PVC in Attachment D and
provide supporting documentation for each score. PG&E will review all submissions and adjust
self-scores as appropriate.
For background, a project’s viability score is based on weighted scores in three categories: 1)
Company / Development Team, 2) Technology, and 3) Development Milestones. The Project
Viability assessment results in a score ranging from 0 to 100 points with 100 being the highest
possible score. Offer information required by PG&E for evaluation of project viability is
described in this 2011 Solicitation Protocol Section VIII.D. The Participant’s claims in all three
categories are verified to the extent possible using publicly available data and/or PG&E data.
This protocol applies to all Offers in this Solicitation.
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4. RPS Goals
a. Overview
PG&E assesses the Offer’s consistency with and contribution to California’s goals for the RPS
program and the Offer’s support of PG&E’s supplier diversity goals (collectively “RPS Goals”).
The RPS Goals assessment considers the factors described below.
b. Methodology
Determination of the extent to which the proposed development supports RPS Goals is based on
the information provided in the Offer as well as PG&E’s assessment of the project (see RPS
Solicitation Protocol Section VIII.D).
1.
Non-quantitative factors identified in CPUC Decision 04-07-029
Benefits to low income or minority communities, Environmental Stewardship, Local
Reliability, and Resource Diversity benefits
2.
Legislative Findings and Declaration that increasing California’s reliance on
renewable energy may do each of the following:

increase the diversity, reliability, public health and environmental benefits of
the energy mix;
promote stable electricity prices;
protect public health;
improve environmental quality;
stimulate sustainable economic development;
create new employment opportunities;
reduce reliance on imported fuels;
ameliorate air quality problems;
improve public health by reducing the burning of fossil fuels;
provide tangible demonstrable benefits to communities with a plurality of
minority or low-income populations.









3.
Consistency with the CPUC’s Water Action Plan adopted on December 15, 2005
and updated October 2010.
To the extent a project uses water on site, its impact on California’s water quality and
consistency with the CPUC’s recommended water conservation practices and goals is
reviewed.
4.
Executive Order S-06-06, signed on April 25, 2006.
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In this executive order, Governor Schwarzenegger described the benefits of biomass
resources in electricity production and established a goal that the state would meet 20%
of its renewable energy needs with electricity produced from biomass. The Participant is
encouraged to describe in its Offer how its ERR facility, if applicable, can support the
20% goal.
5.
Supplier Diversity
In support of PG&E’s supplier diversity goals, the good faith efforts of Participants to
subcontract with Women-, Minority-, and Disabled Veteran-owned Business Enterprises
(WMDVBEs) and if a Participant is a WBE, MBE, or DVBE are factors that are
considered in the bid evaluation process.
5. Transmission Adder
a. Overview
The transmission adder adjusts Offer prices to include the cost, if any, of bringing the power
from the generating facility to PG&E’s network. Once Offers have been ranked on all evaluation
criteria except transmission, the means by which the generation will be delivered to PG&E’s
customers is examined. Each bid is associated with a transmission cluster based upon the
location of the facility. If a CAISO interconnection study has been completed for the project, the
costs in that report are used for bid evaluation. If no study has been completed, the project’s
transmission costs are based upon either the ability to affect deliveries to PG&E’s load through
exchanges, or other commercially-recognized means, or transmission costs are assigned using
the transmission ranking cost report methodology. PG&E uses the lesser of the transmission
adder or alternative commercial arrangements in determining the market value of bids and
selecting the shortlist.
Available capacity at each transmission cluster (if any) is assigned to the bids at each cluster
based on rank. Each bid is then assigned the transmission cost adder indicated by the
Transmission Ranking Cost Report (TRCR) as necessary to accept its project capacity on the
transmission network. The cost adders from the TRCR are provided in Table X.1 in the 2011
Solicitation Protocol.
The cluster-based cost adders are used for bid evaluation only. Resource projects do not have to
physically connect to a cluster, and connecting projects do not necessarily pay the
interconnection prices listed in the TRCR.
b. Methodology for TRCR Adder
After the initial ranking of Offers on Market Valuation, the team calculating the transmission
adder receives a download of data for each Offer. The data is grouped by transmission cluster
and sorted by Market Valuation, from highest to lowest.
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PG&E assigns each Offer an estimated amount of transmission network upgrade costs, if
applicable, using the Transmission Ranking Cost Table X.1 in the 2011 RPS Solicitation
Protocol. Within each of transmission clusters, PG&E has identified various levels of possible
additional transmission capacity, in megawatts, and the related costs, in dollars, of providing that
capacity. These megawatts and dollars in the table are divided between “Peak & Shoulder” and
“Night” periods (note that the dollars for “Baseload & As-Available” columns are simply the
sum of the other two sets of columns minus any common transmission facilities).
Within each of the transmission clusters, and within each period (Peak & Shoulder and Night),
starting with the highest scoring Offer, each Offer is assigned a pro-rata share of the cost. This
share is based on the Offer’s maximum MW as a percentage of the maximum MW of potential
generation assigned to each transmission level based on the initial ranking provided. Offers
whose MWs fall into two levels are assigned a pro-rated cost based on the amount of the Offer’s
MWs in each transmission adder level. For purposes of determining the level to which a
project’s MWs are assigned, only the highest ranking Offer from each Project above it in the
cluster ranking is considered. This rule is intended to prevent the allocation of transmission
capacity to multiple Offers of a single project.
PG&E may accept the electricity at a CAISO delivery point in the PG&E service area or another
delivery point outside of PG&E’s service territory and avoid the cost of congestion through the
use of typical commercial arrangements. Examples of such arrangements include remarketing of
the delivered energy, utility swaps, use of transmission adjustment bids and obtaining
transmission as it becomes available. PG&E utilizes the TRCR values to assess the cost of
transporting the energy to its load center, but PG&E also considers the cost of alternative
commercial arrangements and may choose the most cost-effective option using least-cost best-fit
principles. Ultimately, whether the seller pays for the cost of transmission is negotiable, subject
to PG&E’s ability to recover the cost.
If the proposed Project is located outside the CAISO-controlled grid and is offering delivery
outside the CAISO grid, the Seller is asked to deliver the energy onto or to an intertie with the
CAISO grid. The transmission cost adder is based on the transmission ranking cost at the cluster
closest to the point where its power would enter PG&E's territory (e.g. for power coming in from
the Pacific NW, the cluster would be Round Mountain). This ensures these Offers are properly
valued with respect to Offers with delivery within the CAISO-controlled grid. However, as noted
above, PG&E also considers possible commercial arrangements that might be more economical
than physically transmitting the power to the PG&E service area and will choose the most costeffective option using least-cost best-fit principles.
A Present Value Revenue Requirement (PVRR) is calculated from the Transmission Ranking
Cost table X.1 for each evaluated bid. This PVRR captures from a ratepayer perspective the risk
and cost to construct and maintain transmission upgrades to accommodate the generation from
the renewable resource.
This PVRR of the costs of the Network Upgrades are converted into a present value per MWh
(2011 $ and 2011 MWh) by dividing the PVRR by the Discounted MWh. These present value
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per MWh (2011 $ and 2011 MWh) values, one for each Offer, are returned to the database for a
recalculation of the Market Valuation.
C. Criteria Weightings
1. If a weighting system is used please describe how each LCBF component is
assigned a quantitative or qualitative weighting compared to other components.
Discuss the rationale for the weightings.
PG&E does not apply a weighting system to the LCBF components in the overall
evaluation and selection of Offers.
2. If a weighting system is not used please describe how the LCBF evaluation
criteria are used to rank bids.
As described above, PG&E ranks according to Net Value. Final shortlisting decisions
are made with judgment using the scores and assessments from the other evaluation
criteria. Also, PG&E solicits PRG and IE feedback on the recommended shortlist.
3. Discuss how the IOU LCBF methodology evaluates project commercial
operation date relative to transmission upgrades required for the project.
As described in the Project Viability section above, the effect of the scope and timing
of transmission upgrades on the timing of a project’s commercial operation date is
considered in the viability evaluation.
4. Discuss how the LCBF methodology takes into account bids that may be more
expensive, but have a high likelihood of resulting in viable projects.
The LCBF process considers all Offers on multiple criteria, not just price. All Offers
are scored in each of the criteria and ranked as described above. The Project Viability
score has significant qualitative impact on the final ranking of the Offers. PG&E
notes that the LCBF process is a screening tool that helps with an initial selection of
projects. It is only upon shortlisting that substantive discussions with bidders can
begin.
D. Evaluation of utility-owned, turnkey, buyouts, and utility-affiliate projects
1. Describe how utility-owned projects are evaluated against PPAs
PG&E has not bid any utility-owned projects into its solicitation.
2. Describe how turnkey projects are evaluated against PPAs
All else being equal, a turnkey project is compared to a PPA based on an all-in Net
Value, defined as Market Value after adjustment for Transmission Adders, in
$/MWh. The cost of ownership, measured as a present value of revenue
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requirements, is recalculated to be based in $/MWh. The project with the higher Net
Value is considered better than the one with the lower Net Value, but it is possible
that both could move forward.
3. Describe how buyout projects are evaluated against PPAs
Buyout projects are discussed above.
4. Describe how utility-affiliate projects are evaluated against non-affiliate
projects
PG&E does not have an affiliate that develops renewable energy projects. If PG&E
establishes such an affiliate in the future, there will be detailed protocols to address
such an evaluation in order to ensure fairness to all bidders in the process.
III. Bid Evaluation and Selection Process
A. What is the process by which bids are received and evaluated, selected or rejected
for shortlist inclusion, and further evaluated once on the shortlist?
When bids are received and opened, a processing team reviews each Offer to identify and
summarize key characteristics, and to note any major areas of missing or unclear
information. PG&E has set up evaluation teams for each of the evaluation criteria, as
described above. Each team reviews the entire population of Offers in its evaluation area in
order to ensure consistency in scoring across Offers. A lead person for each Offer ensures
that the scores for that Offer make sense across evaluation teams. If there are any additional
information needs from a bidder, the PG&E lead makes such requests. Responses are taken
into account prior to ranking Offers.
An evaluation committee oversees the integrity of the evaluation process and makes a
shortlist recommendation to the steering committee. The steering committee has the
authority to approve the shortlist and additionally to rule on issues of eligibility. Following
shortlisting, the steering committee approves the priority of negotiations. Offers and their
respective valuations are updated as new information becomes available in the course of
negotiations.
B. What is the typical amount of time required for each part of the process?
For the 2011 RFO, the interval between the issuance of the request for Offers to the receipt of
Offers is approximately five weeks; from the date of bid receipt until notification of bidders
eligible for shortlisting, the interval is about eight weeks; from the date of notification to
transmission of the short list to the CPUC is two weeks. In PG&E’s experience, negotiations
can take from three to six months, or longer, depending on the complexity of the transaction
and the differences between the seller and the IOU. The time from contract execution until
CPUC Approval is generally six to twelve months.
C. How is the size of the shortlist determined?
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The shortlist is sized to create a population of Offers large enough to satisfy PG&E’s
procurement target of 1-2% of load. PG&E takes into account that Offers may be withdrawn
and that negotiations with others may not result in executed contracts.
D. Are rejected bidders told why they were rejected? If so, what is the process?
PG&E notifies rejected bidders by email and provides an opportunity for feedback by phone.
The emails do not specify the reason, but PG&E Offers to discuss the reasons for rejection if
the bidder desires. Several bidders took advantage of PG&E’s Offer.
E. Describe involvement of the Independent Evaluator
The Independent Evaluator (IE) reviews the evaluation criteria, detailed protocols, and the
market valuation and portfolio fit models prior to bid opening. The IE provides feedback on
potential areas for improvement. The IE is present at bid opening and receives a hard copy
and electronic copy of all bid documents. The IE monitors all email communications with
bidders. PG&E uses email exclusively to make supplemental information requests, and all
responses are provided to the IE upon receipt. The IE may submit additional questions that
are not raised by the PG&E team. The IE participates in all meetings of PG&E’s RPS
steering committee and in all PRG meetings related to PG&E’s RPS solicitation. The IE
performs an independent evaluation of the Offers. If any substantive differences exist
between the IE’s evaluation and the utility’s evaluation, the IE discusses these areas with the
utility to determine the reason and to correct the difference.
F. Describe involvement of the Procurement Review Group
For the 2009 RFO, PG&E presented its initial summary and general highlights of solicitation
results to the PRG about a week after bid receipt. PG&E presented a detailed summary and
preliminary shortlist to the PRG about four weeks after bid receipt. Key project
characteristics were discussed. The PRG raised questions and provided initial feedback.
PG&E returned to the PRG with a recommended shortlist about five weeks after bid receipt.
PG&E solicited and incorporated the PRG’s feedback into its selection of the final shortlist
about six weeks after bid receipt. PG&E expects to follow the same process in 2011.
G. Discuss whether and how feedback on the solicitation process is requested from
bidders (both successful and unsuccessful) after the solicitation is complete
Although PG&E has not established a process to receive feedback from bidders, PG&E is
open to providing/receiving feedback, and would consider holding a post-solicitation
workshop or an IE- sponsored survey in order to allow all bidders to express concerns and to
provide/receive feedback. As described above, PG&E talked with several rejected bidders.
In addition, PG&E solicited feedback from all bidders who withdrew from the solicitation, in
order to understand their reasons for withdrawal.
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